Exploring, drilling, completing, and operating hydrocarbon and other wells are generally complicated, time consuming and ultimately very expensive endeavors. In recognition of these expenses, added emphasis has been placed on monitoring and managing all phases of well completion and production. This may include monitoring and maintaining the positioning and placement of well tubulars within a well. For example, the initial drilling of a well may be achieved through use of a drill bit at the end of drill pipe which serves as a tubular for directing fluid flow during the operation. In another example, a tubular in the form of production tubing may be positioned in the well to serve as a conduit for hydrocarbon recovery therefrom. Regardless of the tubular type, proper monitoring and maintenance thereof may substantially lower the cost of well completion and production in the long run.
Monitoring of such tubulars as noted above often reveals problems with their deployment in the well. For example, problems associated with differential pressure, well architecture, obstructions and other factors often lead to the tubular becoming stuck at a location in a well. In the case of drill pipe, this may lead to a stoppage of drilling whereas in the case of production tubing, this may lead to improper or incomplete positioning for hydrocarbon recovery.
Fortunately, techniques have been developed for reversing or “backing-off” tubulars from within the well when such circumstances arise. These techniques take advantage of the jointed nature of tubulars. That is, tubulars are generally made up of a series of tubular portions that are threadably jointed to one another to form a unitary tubular of extended length. Thus, a technique for tubular removal from a well may include breaking a joint of the tubular that is located immediately above the stuck portion of the tubular. In this manner, the portion of the tubular that is located above the stuck portion may be withdrawn from the well, followed by a conventional fishing operation in order to remove the remainder of the stuck tubular.
Unfortunately, techniques such as those noted above for removing the stuck tubular are often fairly hazardous and imprecise. For example, a technique referred to as “stringshot” is often employed. That is, an explosive charge or “stringshot” is delivered downhole to a location adjacent the joint in order to break the tubular thereat. The stringshot technique is hazardous in that the operator is left handling hazardous explosives. However, it is also a fairly imprecise method of breaking the tubular at exactly the location of the noted joint. That is, the tubular may include a series of joints distanced from one another every 20 to 30 feet or so. Thus, given the inherent imprecise nature of explosives, the use of an explosive charge adjacent the intended joint may lead to the breaking of multiple joints both above and below the intended joint. Furthermore, as a result of uneven corrosion or a host of other factors, the intended joint may be more difficult to dislodge or unscrew than other neighboring joints. Therefore, in many cases, neighboring joints may be broken through a stringshot technique while the intended joint remains intact. All in all, employing the stringshot technique to break a tubular at an intended joint is generally considered to be about a 50-50 prospect.
Given the drawbacks to employing a stringshot technique to break a tubular at a desired joint, some added measures have been developed. For example, with the tubular lifted from surface to a vertically compression-free state and having an unscrewing torque applied thereto, a ‘back-off’ tool may be deployed into the tubular to the location of the joint of interest. The back-off tool may be configured to anchor to the upper portion of the joint and rotate in the direction of the unscrewing torque imparted from surface. Thus, the remainder of the unscrewing torque necessary to break the joint may be directed directly to the joint via the back-off tool. Furthermore, the exact joint of interest may more assuredly be broken.
Unfortunately, spacing within the tubular is quite limited. For example, a 5 inch diameter tubular is fairly standard for use in a 12 inch diameter well. Therefore, to ensure that sufficient power is provided to the noted back-off tool, a substantial amount of power may be provided from surface as opposed to disposing large amounts of powering equipment into the tubular. This power may be provided by way of a hydraulic line run from surface to the back-off tool, perhaps several thousand feet into the well and tubular. However, employing hydraulics over such a vast distance may be quite cumbersome and expensive, particularly when dealing with wells of extended reach. Thus, as a practical matter, operators today generally elect to bypass use of such a back-off tool in favor of the more hazardous and less precise stringshot techniques as described above.